1. Field of the invention
This invention relates to hydraulic fracturing in petroleum and natural gas reservoirs, and more particularly to real-time modification thereof by downhole mixing of fracturing components.
2. Background of the Invention
A typical reservoir stimulation process involves hydraulic fracturing of the reservoir formation and proppant placement therein. The fracturing fluid and proppant are typically mixed in pressurized containers at the surface of the well site location. This surface-mixed composite fracturing fluid is generally comprised of an aqueous fracturing fluid, proppant, various chemical additives, including gel polymers, and often energizing components such as carbon dioxide (CO2) and nitrogen (N2). After adequate surface mixing, the composite fracturing fluid is pumped via high-pressure lines through the wellhead and down the wellbore, whereupon ideally the fluid passes into the reservoir formation and induces fractures. Successful reservoir stimulation fracturing procedures typically increase petroleum fluid and gas movement from the fractured reservoir rock into the wellbore, thereby enhancing ultimate recovery.
Reservoir stimulation procedures are capital intensive. Implementation difficulties arise with many known stimulation methods due to various problems, including limitations associated with surface mixing of the stimulation fluid. Typically, a viscous, surface-mixed composite stimulation fluid is injected at pressures adequate to create and propagate fractures in the reservoir. The pressures required to pump such stimulation treatments are relatively high, particularly during injection of the gelled, thickened fluids that may be used to propel proppant into the fractures. These pumping pressures often will increase during the treatment process to an excessive limit, whereupon the operator promptly and prematurely terminates the treatment. Otherwise, serious problems may result, including rupture of surface equipment or wellbore casing and tubulars.
Excessive treating pressures may also occur abruptly during the stimulation fracturing process as a result of premature screenout. Such screenouts are a common problem known in industry that may occur during a fracturing treatment when the rate of stimulation fluid leakoff into the reservoir formation exceeds the rate in which fluid is pumped down the wellbore, thus causing the proppant to compact within the fracture, and into the wellbore. This problem of premature screenout is discussed in U.S. Pat. No. 5,595,245, which is hereby incorporated by reference.
When premature screenout is observed during a fracturing treatment, the operator may elect to reduce the proppant quantity, density, or concentration of proppant per volume of fluid, in order to prevent the occurrence of the screenout. However, when the reduction in proppant concentration is made at the surface, a significant amount of time typically passes before the pumped fluid with altered proppant concentration actually reaches the formation.
A potential problem associated with surface-blended composite fluids is that inhibitors are required to prevent viscous gelling of the stimulation fluid prior to pumping downhole. Highly viscous gels are typically desirable for effective transport of proppant, however, if viscous gelling occurs too early, such as in the tanks and flowlines, or before the fluid is pumped down the well, the efficiency of the overall stimulation job may be compromised due to higher pressures and lower pump rates. To avoid premature gelling, various known chemical inhibitors that include encapsulated or chemically coated inhibitors may be mixed into the composite fluid mixture at the surface to provide a time delayed gelling of the composite fracturing fluid. In addition, other known additives may be incorporated at the surface in an attempt to predictably control the rate of gelling, such as inhibitors to time-delay activation of cross linked polymer gels, which prevents premature gelling of the composite fracturing fluid. A serious shortcoming of this surface-mixed approach, however, is either gelling too early, or too late as evidenced by inadequate gel quality, which frequently results in poor proppant transport and premature screenout.
Typically in many wells the fracturing treatments are terminated prematurely, or reduced in size due to excessive pumping pressures that result from surface mixed and pumped fracturing treatments. In older wells, the premature gelling of the composite fracturing fluid creates a significant potential of exceeding the rated casing or tubing burst pressure. In a 12,000 feet well, for instance, surface wellhead treating pressures often exceed 10,000 psi. whereas bottomhole treating pressures at the reservoir formation depth are significantly higher due to the combination of hydrostatic weight of the composite fracturing fluid (in wellbore) plus surface pumping pressures and friction pressure. The resultant bottomhole treating pressures, if excessive, may crush or fracture proppants in the fracture, which is undesirable due to the release of fines, fracture closure and overall formation damage.
Higher treating pressures are detrimental in terms of requiring lower pump rates, and thereby often alter the overall fracturing stimulation design at the well site. Frequently, the volumetric amount of composite fracturing fluid and proppant that are pumped is lower than desired due to restricted pump rates. Typically higher pumping pressures result in larger horsepower requirements, the usage of more pump engines, and higher cost. Reservoir stimulation fracturing is a capital intensive process, and ineffective reservoir stimulation treatments result in a significant loss of both expended capital and the potential recovery of hydrocarbon reserves.
A typical industry fracturing procedure may commence with mixing of the composite fracturing fluid in storage tanks located on the surface at the well site. The composite fracturing is typically comprised of aqueous gelled fluid, chemical additives and energizers such as N2 and CO2. After mixing, the composite fracturing fluid is pumped via high-pressure lines through the wellhead, down the wellbore and injected into the induced formation fractures. The pumping procedure is typically initiated with the pumping of a pad stage, which is typically fluid without proppant, followed by various stages of fluid containing proppant, and upon termination of the proppant-laden fracturing stage by pumping of the flush stage, which is generally fluid without proppant. This aforementioned sequence occurs when the treatment is pumped as designed, and in the absence of problems including excessive treating pressures and premature screenout.
Another typical industry stimulation technique is known in industry as hydraulic notching or xe2x80x9chydrajettingxe2x80x9d, whereby fluid is injected downhole to cut slots into the production casing or openhole reservoir formation, and thereby induce fractures in the reservoir formation. Conversely this technique may also be used in openhole and horizontal well stimulation procedures. This known stimulation procedure comprises pumping limited proppant concentration during fracturing through casing or in openhole formation, whereby fluid with proppant is typically pumped via tubing through Tungsten jet nozzles that are located at the distal end of the tubing. In the hydrajetting process, mixing of the tubing and annular flow-streams occurs adjacent to the reservoir formation as generally similar fluids are simultaneously pumped down casing. This procedure is typically limited to stimulation applications involving smaller fractures where proppant concentrations are relatively low (usually less than 5 pounds per gallon) in comparison to most typical sand-fracturing techniques, and furthermore the total amounts of proppant that are placed in the fracture are relatively low.
The hydrajetting process may include pumping of different fluids simultaneously down annulus and tubing, in terms of one fluid type consisting of proppant. This process is flexible in allowing different fluid types including acid to be used, but is also relatively expensive in comparison to typical known fracturing techniques. Annular rates are adjusted to maintain fracturing pressures as fractures are generated by the hydrajet fracturing process. A limitation in the use of this system occurs, however, as jets may become eroded during the fracturing injection process, in addition turbulent flow patterns may disperse proppant in the near-wellbore fractures. The proppant washout may be due to a Bernoulli affect, whereby the annular pressures are lower than the fracture tip pressures.
In accordance with the present invention, there is provided a real-time hydraulic fracturing process in which substantial quantities of both nitrogen and carbon dioxide may be separately injected, via the tubing string and casing annulus, to form, in the downhole region of the wellbore, a composite fracturing fluid that may include an aqueous-based fluid, a proppant, N2 and CO2 energizers and various other chemical components. This inventive process may be used to stimulate reservoirs in vertical and horizontal wells, and in openhole and cased wells. The inventive system may also be used for enhanced reservoir recovery procedures to remediate depleted reservoirs in mature fields, via short phase tertiary CO2 injection.
Downhole-blending proximal to the reservoir zone is accomplished by dual injection of different fluids through coiled or conventional tubing and casing annulus. A composite fracturing fluid is thus created downhole prior to injection into the reservoir formation fracture. The aqueous based fracturing fluid may be incorporated into either or both of the gases at the surface and may include proppant and other chemical components, which form the composite fracturing fluid upon mixing downhole. This downhole-mixed fracturing fluid is blended downhole to avoid excessive friction pressures and then injected at a desirable thickened viscosity and at a pressure sufficient to implement hydraulic fracturing of the selected reservoir interval.
Known additives, including thickening agents, may be incorporated into the base-fluid to increase fluid viscosity, to improve proppant suspension, leak-off and related rheological properties. Carbon dioxide may be provided in liquid phase via the tubing and nitrogen may be provided in gaseous phase via the casing, or conversely the carbon dioxide may be injected down the casing and nitrogen down the tubing. Thorough mixing of the propping agent with the composite stimulation fluid preferably occurs immediately above or adjacent to the reservoir interval where the induced reservoir fracture or fractures are propagated. The procedure of downhole-mixing may be accomplished concurrent with tracer monitoring, in real-time, as described in our U.S. Pat. No. 5,635,712 (Scott-Smith), which is hereby incorporated by reference.
In the event of a premature screenout, an operator typically immediately ceases pumping proppant down the casing annulus and the fracturing job is terminated prematurely, or conversely the operator might attempt to abruptly increase the rate of pumping in an often futile endeavor to create new fracture growth, or increase the existing fracture width. However, these known techniques typically do not always yield satisfactory results, and may even worsen the problem in terms of screening out, fracturing out of the desired reservoir zone, or ruining the wellbore casing due to excessive pressures and resultant pipe rupture.
A variety of problems are avoided in real-time by this method of downhole mixing, which provides the ability to substantially instantaneously modify stimulation treatment by rapid changes in pump rate, fluid rheology and proppant concentrations. This inventive system typically minimizes friction pressures and thus provides lower treating pressures and higher pumping and injection rates. Downhole mixing facilitates true real-time modification of the fracture treatment, and provides near instantaneous alteration of fluid viscosity and proppant concentrations at the reservoir, as is described further below.